Referring now to the figures, in many environments crude oil is produced by boring a shaft or borehole 10 into the ground down to a natural reservoir of oil 11 and then inserting a pump into the borehole and pumping the oil out of that reservoir.
The borehole 10 is drilled and then lined with a tubular metal casing 12. The casing 12 is made up of lengths of casing pipe coupled together to form one continuous pipe with a central bore. Each length of casing is in the range of about forty-four feet long and has male threads at both ends, joined together with female-female threaded collars 16 to form the continuous tube with an interior bore. A collar 16 generally is a short length of pipe with female threads on either end that acts as a coupling to join two lengths of pipe, here casing 12 pipe having male threads at each end. When the male threads of two casing pipes are inserted into a collar there is a short gap within the collar between the ends of adjoining lengths of casing pipe.
Oil reservoirs 11 may be relatively deep, perhaps 6,500-11,000 feet deep, and the borehole may need to be drilled through several zones of different material found at lesser depths, such as an aquifer that might be found at a relatively shallow 1,500 feet or less below the surface. In addition to the casing 12 of the borehole 10, cement may be poured around the outside of the casing to seal the walls of the borehole from the surrounding material. This seal is created both to prevent oil leakage out of the borehole and fluid leakage into the borehole from the various surrounding zones of material. This seal may be critical in order to prevent the oil from leaking out of the borehole and contaminating a surrounding aquifer that the borehole passes through.
At the terminal or bottom end of the casing 12, where the borehole 10 intrudes into an oil reservoir or oil sands zone 11, a final section of liner 14 pipe is placed and hung with liner hanger to the end of the casing, forming a single continuous bore through the casing and liner pipe.
A joint 18 refers generally to a single length of pipe, for example liner, casing, or tubing that has threaded connections at both ends. Joints 18 are made in standard lengths depending on the type of pipe. Several joints 18 coupled together are called a stand of pipe and a string of pipe refers to the entire length of all the joints of pipe or tube used in the length of the borehole. A pup joint 20 is a joint of less than standard length. The shorter lengths of pup joint production tubing are used to adjust the total length of a stand or string should the desired length be less than exactly a multiple of the standard lengths, to add a length of pipe of less than a whole standard length to more precisely size the total length of the string.
Typically the liner 14 pipe used has a narrower internal diameter than that of the casing pipe it is used with, for example a typical industry standard uses a casing 12 having an internal diameter of 8⅝ inch and is used with a liner pipe having a narrower 6⅝ inch internal diameter. The liner 14 pipe is also different from the casing 12 in that the liner is not sealed from the surrounding material and is instead perforated with voids or slots 14A. The liner 14 is inserted into an oil reservoir or oil sands zone 11 and allows oil from the reservoir or reservoir sands 11 to seep through the perforations 14A into the liner. The voids 14A of the liner 14 may be slots that are small enough to keep most surrounding sand out of the liner while allowing the crude oil to seep into the liner.
An electric submersible pump 22 comprised of various components including an impeller and electric motor is lowered into the casing and is hung atop the opening of the liner 14 pipe. The electric motor portion of the pump 23 is usually located at the bottom of the submersible pump 22 and is sized to fit within the casing 12.
The electric pump 22 has couplings or flanges at each end to allow several pumps to be connected in series as a single pump and the pump sucks liquid that's entered from the liner 14 section at the lower end, the intake opening 22A and expels it through the second upper opening at the top of the pump, the exhaust opening 22B, at the opposite end of the pump. Production tubing or line 24 is affixed to the exhaust opening 22B to achieve liquid communication with the pump. The production tubing 24 connected to the pump 22 runs from the pump to the surface within the length of the casing 12. The electric pump 22 and production tubing 24 together form a single liquid conduit through which oil is pumped from the liner 14 through the production tubing to the surface.
The motor 23 of the electric pump 22 is sized to fit snugly within the casing and therefore has an outside diameter larger than that of the liner 14 section, preventing the electric pump motor from entering the liner section. In cases where the diameter of the pump motor may be less that of the liner, the pump may include a No-Go 26, which are flanges or protuberances or wings 26A affixed to and protruding from the electric pump or other tools that are lowered into the casing. The No-Go 26 functions to maintain a sufficient outside diameter so as to interfere with the internal diameter of the liner pipe 14 section, thereby preventing that pump or tool from entering the liner section.
The production tubing 24 is usually of substantially smaller outside diameter than the casing 12 internal diameter that it is placed in. In the example used the production tubing 24 may have an outside diameter of 2⅞ inches. As with the casing pipe 12, each joint of the production tubing 24, including pup joints 20, has two male ends. A collar 16 is used to connect two joints together to form a stand or string of production tubing 24. Production tubing 24 joints are joined together with production tubing collars 16 to form a string of production tubing connected to the electric pump 22 and traversing the length of the casing.
The electric pump motor 23 requires an electric power supply to operate and therefore an electric cable 28 of about 1¼ inches in diameter is plugged into the pump motor 23. Flat cable is plugged into the pump directly, runs up the productions line 24 for a joint or two, then the 1¼ cable is used, which runs the length of the production tubing to a power source located on the surface. Metal bands 30 are installed around the production tubing 24 and electric cable 30 at intervals to hold them together to prevent the electrical cable from becoming entwined, jammed or knotted up when the production tube is inserted or withdrawn from the casing 12. The bands 30 are typically metal strapping affixed around the electric cable and crimped together with a saddle fastener (not shown). The pump uses a flat special banding, flat guards banding to band the flat cable to the pump.
The bands 30 are affixed around the production tubing 24 and electrical cable 28, and, around the electric pump 22 and electric cable 28 as the stand of pipe is assembled and lowered into the casing 12. The bands 30 are typically placed on either side of the production tubing collars 24A as joints are added. A count is kept of the number of bands affixed to the production tubing determine how many may be missing when the string is eventually removed from the casing 12.
A problem arises as the string of production tubing 24 and pump 22 is withdrawn from the casing, for example to service the electric pump. The bands 30 may rub against the interior wall of the casing 12 or snag on the gaps in the casing collars and then the bands sometimes break and fall off into the casing. The broken bands 30 may occlude the casing 12, jamming the casing and making it difficult to reinsert the electric pump 22 and string of production tubing 24 for example.
This band debris problem is especially acute in a deviated drill borehole where the borehole was drilled with a deviation from vertical. Many or most modern oil well boreholes are not vertical shafts, they bend at several junctures and some run horizontally for great distances. The act of withdrawing the pump from a casing that is not oriented vertically exacerbates the damage to the bands because the weight of the production tubing make it more likely that the bands will rub against or be dragged along the interior of the casing, breaking the bands.
This problem is addressed by clean-out procedures. The number of bands 30 affixed to a production tubing 24 string are counted when the production tubing is inserted and, should there be bands missing after the production tube string is withdrawn from the casing 12, the casing must be cleaned out. The broken bands usually have to be extracted from the casing before the pump can be again placed in the casing. The present methods of cleaning out an oil well casing of broken bands and other debris are expensive, laborious and very time-consuming, keeping the oil well out production during the cleanout procedure.
If there are bands missing from those counted after the production line is withdrawn a two-stage cleanout operation typically is performed. In the first stage of the cleanout operation a surge tool 32 is inserted down the length of the bore. A surge tool 32 has a rubber packoff cup 32A that is sized to snugly fit within the inside diameter of the casing 12 to form a seal. The surge tool 32 has a central opening with a junk catcher 34 mounted within the central opening to create a one-way trap for debris to pass through as the surge tool is inserted. The junk catcher includes a radial array of fingers 34A that are spring-biased to bend into the surge tool only, to allow debris to pass into the body of the surge tool, then snap closed to retain the debris. The surge tool 32 is affixed to a length of perforated pup joint 32B at the end opposite the junk catcher and the pup joint is also attached to the production tubing string. As the surge tool 32 is inserted into the casing 12 most liquid and debris in the casing will be forced through and be trapped by the junk catcher 34 within the surge tool. As the surge tool is withdrawn the pup joint perforations allow liquid to still pass even when the debris trapped by the junk catcher clogs the bottom of the surge tool.
The surge tool 32 is lowered into the casing the entire length by affixing successive lengths of production tubing 24, then withdrawn. The debris and broken bands are thereby trapped within the surge tool 32 as it is inserted and are collected for disposal as the surge tool is pulled to the surface.
This first surge tool operation is time consuming and may take four to six hours to complete.
After the surge tool operation has been completed a second cleanup operation is conducted to pulverize any remaining contaminants, bands or other debris still in the casing and missed by the surge tool operation. In the second stage of the cleanout operation a grinding head 36 is inserted down the length of the bore. Like the surge tool 32 the grinding head 36 also has a central opening with a junk catcher 34 mounted within the central opening to create a one-way gate for debris to pass through as the surge tool is inserted. The outer edge of the grinding head 36 surrounding the junk catcher 24 is comprised of a rough material made of a hard metal such as tungsten-carbide. The grinding tool is affixed to production tubing 24 and lowered the length of the casing 12. As the grinding head 36 encounters debris or broken bands it grinds them up and the ground-up debris is forced through the junk catcher 34, to be withdrawn later with the grinding head for disposal. This second separate operation is also time-consuming and may take another four to six hours or longer to complete.
What is needed then is a device and method for more easily and reliably removing any broken bands, reducing the need for these cleanup operations.